This section is intended to introduce various aspects of the art, which may be associated with exemplary embodiments of the present disclosure. This discussion is believed to assist in providing a framework to facilitate a better understanding of particular aspects of the present disclosure. Accordingly, it should be understood that this section should be read in this light, and not necessarily as admissions of prior art.
Storage of carbon dioxide (CO2) and associated gases in deep fluid-filled formations will most likely be the major component of geologic storage to mitigate carbon dioxide emissions to the atmosphere. This is supported by the Intergovernmental Panel on Climate Change (IPCC) special report on carbon dioxide capture and storage and subsequent researchers who have estimated that the storage capacity in deep fluid filled formations is sufficient to hold worldwide emissions from large stationary sources equivalent to 100 or more years capacity. These formations have at least 10 times the capacity of known oil and gas fields and 100 times the capacity of coal seams. In addition, deep fluid filled formations are often located in close proximity to large stationary sources of CO2 so the cost of transport (usually by pipeline) can be minimized. The above capacity estimates however, assume that in-situ brine in the deep fluid filled formations can and will be displaced in the vicinity of injection sites and that pressure containment by overlying primary caprock layers will be effective.
Safe storage means that buoyant carbon dioxide (CO2) and associated gases, collectively referred to as gaseous emissions (GE) injected into a fluid filled subterranean formation will not leak upwards, over the long term, to either the potable ground water (usually near the surface) or to the atmosphere.
Efficient storage generally involves supercritical phase GE injection that utilizes as much of the permitted pore space as possible within the vertical thickness of the deep fluid filled formation. The US National Energy Technology Laboratory (NETL) defines safe and efficient storage as having 99% permanence and 30% efficiency. Permits for storage will, in most jurisdictions, be granted for a defined geographical area and allowed only in porous intervals that are deemed to be deep enough for both safe and efficient storage. A commonly quoted depth for CO2 to be in supercritical phase is greater than 800 meters below surface. At this depth, or greater, the in situ fluid is usually a high salinity brine so the literature often refers to target storage reservoirs as “deep saline formations”. There will likely be multiple stakeholders involved in the leasing and permit process and multiple storage areas may be permitted within a given deep fluid filled formation. It is therefore in the interest of all parties to confine the injection plume to as small an area as possible and to operate the injection site at a safe pressure in the subsurface.
Current carbon dioxide disposal systems into deep fluid filled formations will either increase pressure in the low compressibility fluid filled formation and/or displace fluid(s) outside the vicinity of the injection well(s) and possibly outside of the permitted area. In addition, the density of the injected gases (including supercritical phase carbon dioxide) is less than the in-situ fluid (“dense fluid”) resulting in buoyant gas override and possible upward leakage over time through overlying primary caprocks and possibly other confining strata.
Risks of injection operations to be mitigated include: cap rock fracturing (when subjected to high injection pressures), cap rock leaching by the slightly acidic injected gas—dense fluid mixture and/or excursion of the mixed fluids within the storage reservoir outside the permit area and/or into overlying confining strata, potable water aquifers, the oceans or the atmosphere.
Small scale (about 1 Mega tonne/year of CO2) demonstration projects to date have assumed that an injection storage solution will be able to accommodate the necessary volumes of injected CO2 when done in high-capacity fluid filled formations. An implicit assumption in models of these demonstration projects done to date is that the in-situ fluid will be displaceable away from the injection site when injection is done at a larger scale (˜100 Mega tonne/year of CO2). Example projects with one or two wells utilizing injection-only fluid displacement technology include Sleipner and Snohvit in the Norwegian North Sea, In Salah in Algeria, Ketzin in Germany and LaBarge in the USA. The Sleipner plume has been imaged utilizing repeat seismic surveys that show both upward migration of the plume from the horizontal well to the caprock and spreading away from the point of injection. Models have also been constructed for the above examples to gain better understanding of the impact of plume buoyancy causing both upward movement to the base of the caprock and lateral migration away from the injection well.
What is needed are new approaches to sequestering large volumes of gaseous emissions (GE) in subsurface reservoirs, for long periods of time, while mitigating the risk of over pressuring and possible plume seepage to the surface or into adjacent formations that may contain valuable or fragile natural resources.
Some material relevant to the problem of CO2 storage in deep saline aquifers includes: WILKINSON, S, et al., (2009) “Subsurface design considerations for carbon dioxide storage”, GHGT-9, Energy Procedia I, 3047-3054; and accompanying presentation materials of November 2008; NORDBOTTEN, C., et al., (2005) “Injection and Storage of CO2 in Deep Saline Aquifers: Analytical Solution for CO2 plume evolution During Injection” Transp. Porous Med. 58:339-360.; STAUFFER, P.H., et al., (2008): “Combining geologic data and numerical modeling to improve estimates of the CO2 sequestration potential of the Rock Springs Uplift, Wyo.”, GHGT-9, Washington D.C., November 2008, Energy Procedia 00 (2008) 000-000; KUUSKRAA, V. A., et al., (2009) “Using reservoir architecture to maximize CO2 storage capacity”, GHGT-9, Energy Procedia 1 3063-3070; and accompanying presentation materials of November 2008.; LEONENKO, Y., et al., (2008) “Reservoir Engineering to accelerate the dissolution of CO2 stored in aquifers”, Environ. Sci. Technol 42, pp.2742-2747.